Academic literature on the topic 'Fault plane solution (FPS)'

Abstract Photoluminescence, defect-band emission, and Lock-in Infrared Thermography (LIT) generally enable the correlation of multi-crystalline silicon defect types. Long Wavelength Infrared (LWIR) thermal imaging has traditionally seen limited application in failure analysis. LWIR cameras are typically uncooled systems using a microbolometer Focal Plane Arrays (FPA) commonly used in industrial IR applications, although cooled LWIR cameras using Mercury Cadmium Tellurium (MCT) detectors exists as well. On the contrary, the majority of the MWIR cameras require cooling, using either liquid nitrogen or a Stirling cycle cooler. Cooling to approximately −196 °C (77 K), offers excellent thermal resolution, but it may restrict the span of applications to controlled environments. Recent developments in LWIR uncooled and unstabilized micro-bolometer technology combined with microscopic IR lens design advancements are presented as an alternative solution for viable low-level leakage (LLL) defect localization and circuit characterization. The 30 micron pitch amorphous silicon type detector used in these analyses, rather than vanadium oxide (VOx), has sensitivity less than 50mK at 25C. Case studies reported demonstrate LWIR enhanced package-level and die-level defect localization contrasted with other quantum and thermal detectors in localization systems.

Abstract Two-dimensional plane strain models are used frequently to evaluate depletion induced fault instability in permeable reservoirs. However contrary to depletion induced fault instability thermal stress induced fault instability by cold fluid injection is local in nature and the applicability of plane strain models is not straightforward. This paper investigates (A) the accuracy of two-dimensional plane strain (2D-PS) models to evaluate thermal-stress induced fault instability and (B) the requirement to correct elastic solutions for the occurrence of excessive tensile stress. Similar to depletion induced compaction, shear stress significantly contributes to the initial fault criticality ahead of a cold front causing contraction (Stage 1). Only after the cold front intersects with a fault (Stage 2), fault criticality is completely dominated by normal stress reduction. Compared to a full 3D model, a two-dimensional Plane Strain model slightly exaggerates the onset of fault criticality during stage 1 as it gives higher maximum principal and shear stress ahead of the cold front. During stage 2, Plane strain models overpredict horizontal stress arching above and below a thermally compacting body compared to full 3D, which may result in some slight underprediction at intermediate times. However, with a growing cold front in time the deviation converges as the transition from critical to stable occurs at the same depth around the horizontal center axis of the cold front. For increased elongation of the 3D cold front along the constant-axis of the plane strain model, plane strain model results converge to the full 3D model results while the deviation between elastic and tensile stress corrected models converges to a constant offset. Overall, Plane strain models that are corrected for excessive tensile stress provide an efficient but slightly conservative method to access full 3D fault stability behavior by cooling. In case of severe thermal stress reduction, excessive tensile stress has to be compensated because the elastic solution will exaggerate the onset and magnitude of fault criticality as it gives too low minimum principal stress and too high shear stress.

Abstract A complex fault-block reservoir usually has large layer span, many thin layers and oil-water systems. The available data are limited in the exploration stage. One of the biggest advantages is that each well is tested several times. Based on comprehensive geological study, this paper proposed a well testing analysis methodology to carry out reservoir evaluation, and the results are applied to the oilfield development plan. Well testing can reflect the static and dynamic characteristics of reservoir at the same time. It shows high application value in the exploration stage. The analysis methodology of well testing in complex fault-block oilfield mainly includes three aspects: (1) Establish a novel calculation method to obtain crude oil parameters of all tested intervals, which are necessary in well test interpretation. (2) Build reliable interpretation models to evaluate wellbore, formation property, productivity and boundary according to pressure derivatives curves. (3) Propose a concise evaluation process to show reservoir characteristics in both vertical and plane. This methodology is applied in Doseo Oilfield and proved to be a great methodology in complex fault-block reservoirs. The calculated crude oil parameters are good matched with limited PVT data. The errors are less than 10%. The formation characteristics obtained from the models including permeability, faults and aquifer energy are well verified by seismic and well-logging interpretation. The reservoirs in middle area on the plane and Zone K in the vertical show high productivity and permeability. They can be selected as the key oil regions for the first production. Similar formation characteristics are reflected by the analogous shape of pressure derivatives. They can be put into production with the same development methods to obtain higher benefits. The innovation is that this paper proposes an analysis methodology of well testing to calculate right crude oil parameters, identify formation characteristics and key oil regions, and find similar reservoirs. It can decrease the errors which are caused by parameter uncertainties and multi-solution of interpretation models.

Abstract Equinor has a complex faulted field in Norway with expected different fluid contacts. To maximize the reservoir understanding a geoscience approach is applied for this project. The utilization of Ultra Deep Azimuthal Resistivity (UDAR) technologies is typically sufficient to control the vertical and lateral limits of a reservoir and unveil potential flooded intervals and oil water contacts (OWC). However, the differentiation between oil and gas by just LWD and UDAR data is not possible. This study demonstrates three geoscience areas contributing for early decision making while drilling the Brent Group formation. The cost-effective solution in this project was the implementation of advanced mud gas (AMG) using a constant volume and constant temperature (CVCT) extractor with advanced gas chromatograph to analyze species such as methane to octane. Correction for recycling gas and extraction efficiency correction (EEC) of methane to pentane species were also applied in real time (RT). The gas ratios curves were the first look of the PVT for this well, therefore the gas oil ratio (GOR) prediction based on the model proposed by Yang et al., 2019 were also available and provide reservoir insight while drilling. The High-Resolution ultrasonic image tool was used to detect bedding, fractures and faults planes post-drilling, and in conjunction to UDAR results several diagrams such as Stereonet plot and curtain sections were displayed. Additionally, an ultrasonic caliper tool was used to identify the borehole shape. The sandstone bedding plane orientation showed several trends inside the whole interval and most of these changes were associated with faulted intervals and validated with Geosteering inversion model. The fault system understanding is important in this basin since it contains a western graben created by several faults stepping down preserving Upper Brent. Petrophysical analysis complements and supports the results from AMG, UDAR and borehole image analysis. The basin setup is helpful to understand the fluid distribution in the petroleum system. From a petrophysical viewpoint, water saturation from resistivity logs and neutron-density separation helped to estimate fluid types, and it was validated with AMG. The identification of 300m of water flushed zone, later confirmed by production, shows the holistic methodology implementation allowed a review of the fluid distribution in the well results. This paper demonstrates the contribution of the race to digital transformation and enabled reservoir characterization while drilling.

Abstract High gas flow rates in deep-buried dolomitized reservoir from an offshore field Abu Dhabi cannot be explained by the low matrix permeability. Previous permeability multiplier based on distance to major faults is not a solid geological solution due to over-simplifying reservoir geomechanics, overlooking folding-related fractures, and lack of detailed fault interpretation from poor seismic. Alternatively, to characterize the heterogeneous flow related with natural fractures in this undeveloped reservoir, fracture network is modelled based on core, bore hole imager (BHI), conventional logs, seismic data and test information. Limited by investigation scale, vertical wells record apparent BHI, and raw fracture interpretation cannot represent true 3D percolation reflected on PLT. To overcome this shortfall, correction based on geomechanics and mechanical layer (ML) analysis is performed. Young's modulus (E), Poisson ratio (ν), and brittleness index are calculated from logs, describing reservoir tendency of fracturing. Other than defining MLs, bedding plane intensity from BHI is also used as an indicator of fracture occurrence, since stress tends to release at strata discontinuity and forms bed-bounded fractures observed from cores. Subsequently, a new fracture intensity is generated from combined geomechanics properties and statistics average of BHI-derived fracture occurrence within the ML frame, which improves match with PLT and distinguishes fracture enhance flow intervals consistently in all wells. Seismic discontinuity attributes are used as static fracture footprints to distribute fractures from wells to 3D. The final hybrid DFN comprises large-scale deterministic zone-crossing fractures and small-scale stochastic bed-bounded fractures. Sub-vertical open fractures are dominated by NE-SW wrenching fractures related with Zagros compression and reactive salt upward movement. There is no angle rotation of fractures in different fault blocks. Open fractures in other strikes are supported by partial cements and mismatching fracture walls on computerized tomography (CT) images. ML correlation shows vertical consistence across stratigraphic framework and its intensity indicates fracture potential of vertical zones reflected by tests. Fracture-enhanced flow units are further constrained by a threshold in both combined geomechanics properties and statistics average of raw BHI fracture intensity in ML frame. As a result, final fracture network maps reservoir brittleness and flow potential both vertically and laterally, identifying fracture regions along folding axis not just major faults, evidenced by wells and seismic. According to the upscaling results, the case study reveals a type-III fractured reservoir, where fractures contribute to flow not to volume. Fracture network enhances bed-wise horizontal communication but also opens vertical feeding channels. Fracture permeability is mainly influenced by aperture and intensity, while aspect ratio, fracture length, and proportion of strikes and dips mainly influence permeability distribution rather than absolute values. This study provides a production-oriented characterization workflow of natural fracture heterogeneity based on correction of raw BHI in undeveloped fields.